Reacting Ions Method to Identify Injected Water Fraction in Produced Brine

Abstract

Waterflooding is a very common method of oil displacement and pressure support. One particular problem that may arise after injection water (IW) breakthrough at the production well is the formation of sulphate scale. One of the main parameters that determines the severity of this type of scale formation is the amount of injection water/formation water (IW/FW) mixing that has taken place. Thus, the injected water fraction in the produced brine mix is an important value to determine. Our ability to model scale precipitation in situ and in the well is linked to our ability to accurately determine the IW fraction at production wells. Current industry practice is to work on an analytic approach for determining the fraction of IW in the produced brine stream in general, and for identifying IW breakthrough in particular. A robust and accurate method for determining IW fraction in field produced water analysis is required to match the modelled IW fractions. When this is achieved, it is possible to use various modelling techniques with a higher degree of confidence to predict future scaling tendencies, and to help implement an appropriate scale management strategy to economically mitigate the potential effects of scale damage. In this paper, the "Reacting Ions" method is introduced for determining the fraction of IW (and FW) in produced waters. This method is then applied to a synthetic produced water case where the "correct" answer is known, and a very good match is achieved, even when significant noise is applied to the synthetic data. The method is then applied in the analysis of produced brines for several wells in a North Sea field. Results of the study presented here show that the method is more effective in detecting IW fractions than conventional ion tracking techniques, especially at low IW fractions close to when breakthrough occurs. The significant new development presented in this work is that this approach may be used accurately even in situations where scale deposition deep in the reservoir impacts the concentrations of the ions used in this method. Introduction Water is a universally occurring natural solvent in all sedimentary systems where petroleum is found. In contact with rocks, water may dissolve minerals in the matrix, and so subsurface waters are usually solutions containing a wide variety of ions, including Na+, Ca2+, Mg2+, Cl-, etc. The properties which may be used to characterise subsurface brines include temperature, chemical composition, pH, amount of total dissolved solids (TDS) and resistivity. Waters held in deep formations over geological timescales are often referred to as formation water (FW). The properties of subsurface waters vary significantly from one reservoir to another. The chemical compositions may range from relatively fresh waters, evaporated sea water or to highly concentrated brines. Hydrocarbons in reservoirs are coupled with subsurface waters which in turn play an important role in the original hydrocarbon migration and accumulation. Water deep in reservoirs can be present as a result of trapping during sedimentation or filtration, or a combination of both mechanisms (Ostroff, 1975). Over geological timescales, the subsurface waters come into chemical equilibrium with the rock and the hydrocarbons. In the oil industry, waterflooding is a widely applied secondary recovery method. During a waterflood, injection water (IW) is pumped into injection wells into the reservoir to displace mobile oil towards the production wells, and to provide energy to lift hydrocarbons to the surface (Dake, 1978; Craig, 1980; Willhite, 1986; Lake 1989). During water injection, subsurface formation waters (FW) are displaced along with the hydrocarbons, and are often produced in a IW/FW mixture that may contain a range of cations and anions as well as rock particles, sand, hydrocarbons drops, etc. The amount of produced water from a production well (and from an entire reservoir) generally increases with time.

Predicted and Observed Evolution of Produced-Brine Compositions and Implications for Scale Management

“…The risk of scale formation depends on both the SR and the local environment. Oversaturation (SR > 1) means that the system is no longer in chemical equilibrium, and the force that drives scale precipitation is greater at larger values of SR. A thermodynamic scale-prediction code (Kaasa 1998) was used to calculate SR and mass that would precipitate on the basis of various ratios of FW/IW mixtures. The thermodynamic model results in Figs.…”

A Critical Review of Emerging Challenges for the Oil Field Waters in the United States

“…The salinity of the water will depend primarily on the concentration of Na ϩ and Cl -ions. Although these ions may occur naturally in produced water, water injection processes may also alter the chemical composition of the subsurface water due to ion exchange, precipitation, and dissolution (Ishkov et al 2009). This may lead to the formation of a wide variety of scales (Qu et al 2013).…”

Sequential Coupling of Geochemical Reactions With Reservoir Simulations for Waterflood and EOR Studies

“…Moreover, the costly interwell tracer tests can be eliminated if water compositions have been monitored carefully. This can signifi cantly improve the characterization of geologically complex and heterogeneous reservoirs under waterfl ood [Ishkov et al (2009) …”